Methods and apparatus for locating a lateral wellbore

ABSTRACT

The present invention relates generally to lateral wellbore operations, and more particularly, to downhole tools that include a logging tool for locating a lateral wellbore and associated methods. In some embodiments, the present invention discloses a method for use in lateral wellbore operations that includes entering a lateral wellbore from a primary wellbore with a tool comprising a logging tool, and verifying entry into the lateral wellbore using the logging tool. In yet other embodiments, the present invention discloses methods of locating lateral wellbores from a primary wellbore, and downhole tools that comprise logging tools, such as casing collar locators, radiation detection logging tools, or combinations thereof.

BACKGROUND

The present invention relates generally to lateral wellbore operations,and more particularly, to downhole tools that include a logging tool forlocating a lateral wellbore and associated methods.

Operators seeking to produce hydrocarbons from subterranean formationsoften employ multilateral wells. Unlike conventional vertical wells,multilateral wells include a primary wellbore and a series of lateralwellbores that branch from the primary wellbore. The primary wellboremay be a generally horizontal, generally vertical, or otherwise formedportion of a wellbore. Although multilateral wells are often moreexpensive to drill and complete than conventional wells, multilateralwells are generally more cost-effective overall, as they usually havegreater production capacity and higher recoverable reserves. Becausefewer multilateral wells than conventional wells are needed to recoverthe same amount of hydrocarbons, overall drilling and capital expensesmay be reduced. In addition to being cost-effective, multilateral wellsare also an attractive choice in situations where it is necessary ordesirable to reduce the amount of surface drilling operations, such aswhen environmental regulations impose drilling restrictions.

Although multilateral wells may offer advantages over conventionalwells, they may also involve greater complexity, which may poseadditional challenges. One such challenge involves the location andentry of specific laterals that branch from the primary wellbore. Forexample, working over a lateral wellbore may be complicated by problemsassociated with locating and entering the lateral wellbore. A number oftechniques have been developed for locating and entering the laterals sothat lateral wellbore operations may be performed. As defined herein,“lateral wellbore operations” are defined to include any suitablesubterranean operation that may be performed in a lateral wellbore usinga downhole tool, including, but not limited to, jetting, logging,analyzing, stimulating, cementing, or other suitable operations known tothose of ordinary skill in the art. One such technique for locating andentering lateral wellbores involves the installation of special jewelryin the casing at the junction of the lateral and primary wellbores. Thisjewelry allows the landing of whipstocks adjacent to the junction toforce any subsequent tubing run into the primary wellbore into thedesired lateral wellbore. However, this technique is undesirable, interalia, because the special jewelry generally may not be added after theprimary casing is cemented in place. Furthermore, installation of thespecial jewelry may add undesirable expense to the completion of thewell.

Another technique for locating and entering a lateral wellbore involvesthe utilization of a downhole tool that comprises an indexing tool, akickover knuckle joint attached at a lower end of the indexing tool, anda wand attached at a lower end of the kickover knuckle joint. Coiledtubing may be run into a primary wellbore with the downhole toolattached at an end thereof. The downhole tool may first be lowered tothe bottom of the primary wellbore to tag the bottom thereof andestablish a maximum depth. After recordation of this depth, the downholetool may then be raised to the estimated location of a junction of alateral wellbore with the primary wellbore. At this point, the kickoverknuckle joint may be used to deflect the wand away from the longitudinalaxis of the downhole tool, and the downhole tool may be raised orlowered in the primary wellbore. To orientate the downhole tool in theprimary wellbore, the indexing tool may be used to rotate the wandrelative to the coiled tubing. When a lateral wellbore is located, thetip of the wand is allowed to fully bend into the lateral wellbore.Accordingly, when the wand fully bends, pressurized fluid in thedownhole tool may be vented, which may be sensed at the surface therebyproviding a surface indication to the operator that a lateral wellborehas been located. Because the wand controls the venting process,selection of the appropriate wand length may be critical in locating thelateral.

This technique, however, has drawbacks. One drawback with this techniqueis that the downhole tool may not include a means for accurate depthcontrol downhole. For example, standard coiled tubing depth measurementmay be off by as much as 100 feet. Therefore, when the downhole tool israised to the estimated location of the junction, the location of thedownhole tool may not be near the actual location of the junction so thedownhole tool may be searching for the junction in the wrong location.Another drawback with this technique is that the venting portion of thedownhole tool may not reliably signal the operator that a lateralwellbore has been located. In some instances, the tip of the wand maynot fully bend even though it is in a lateral wellbore so that noventing takes place. Even further, for example, the downhole tool mayvent when it is not in the lateral wellbore, inter alia, becausecurvature of the coiled tubing above the downhole tool may be sufficientto allow for the wand to fully bend. Because of these possibleinaccuracies with the venting portion of the downhole tool, once theoperator believes that a lateral wellbore has been located, the operatoroftentimes will lower the downhole tool to the bottom of the lateralwellbore to tag the bottom thereof. This depth may be compared with thepreviously recorded depth of the primary wellbore to determine if alateral wellbore has been found. If the two depths are identical, alateral wellbore has not been found, and the operator must repeat theprocedure for locating a lateral wellbore. The necessity for tagging thebottom of the primary and lateral wellbores may add undesirable delaysto lateral wellbore operations.

SUMMARY

The present invention relates generally to lateral wellbore operations,and more particularly, to downhole tools that include a logging tool forlocating a lateral wellbore and associated methods.

In one embodiment, the present invention provides a method for use inlateral wellbore operations. The method includes entering a lateralwellbore from a primary wellbore with a tool comprising a logging tool.The method further includes verifying entry into the lateral wellboreusing the logging tool.

Another embodiment of the present invention provides a method oflocating a lateral wellbore of a multilateral well, wherein themultilateral lateral well comprises a primary wellbore and a lateralwellbore that branches from the primary wellbore at a junction. Themethod includes positioning a tool comprising a logging tool within themultilateral well. The method further includes moving the tool withinthe multilateral well. And the method further includes determiningwhether the tool has entered the lateral wellbore using the loggingtool.

Anther embodiment of the present invention provides a method of locatingand entering a lateral wellbore from a primary wellbore, the lateralwellbore branching from the primary wellbore at a junction. The methodincludes positioning a downhole tool in the primary wellbore at a firstlocation posterior to the junction, the downhole tool comprising acasing collar locator. The method further includes positioning thedownhole tool in the primary wellbore at a second location anterior tothe junction subsequent to positioning the downhole tool in the primarywellbore at the first location. The method further includes moving thedownhole tool from the second location towards the junction. And themethod further includes determining whether the downhole tool hasentered the lateral wellbore using the casing collar locator.

Anther embodiment of the present invention provides a method of locatingand entering a lateral wellbore from a primary wellbore, the lateralwellbore branching from the primary wellbore at a junction. The methodincludes positioning a downhole tool comprising a radiation detectionlogging tool in the primary wellbore. The method further includes movingthe downhole tool towards the junction. And the method further includesdetermining whether the downhole tool has entered the lateral wellboreusing the radiation detection logging tool.

Another embodiment of the present invention provides a downhole tool,the downhole tool including a logging tool. The downhole tool furtherincludes a kickover knuckle joint connected to the logging tool. And thedownhole tool further includes a wand connected to the kickover knucklejoint. Optionally, an orienting sub may be connected between the loggingtool and the kickover knuckle joint.

The features and advantages of the present invention will be readilyapparent to those skilled in the art upon a reading of the descriptionof embodiments that follows.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete understanding of the present disclosure and advantagesthereof may be acquired by referring to the following description takenin conjunction with the accompanying drawings, wherein:

FIG. 1 is a schematic drawing depicting a downhole tool in accordancewith an embodiment of the present invention.

FIGS. 2 a and 2 b are side-cross sectional views depicting a casingcollar locator in accordance with an embodiment of the presentinvention.

FIG. 3 is a side-cross sectional view depicting a radiation detectionlogging tool in accordance with an embodiment of the present invention.

FIG. 4 is a side-cross sectional view drawing depicting a combinationcasing collar locator/radiation detection logging tool in accordancewith an embodiment of the present invention.

FIG. 5 a is a schematic drawing depicting a cased lateral wellbore thatbranches from a primary wellbore, and a downhole tool of the presentinvention disposed at a first location in the primary wellbore inaccordance with an embodiment of the present invention.

FIG. 5 b is a schematic drawing depicting an uncased lateral wellborethat branches from a primary wellbore, and a downhole tool of thepresent invention disposed at a first location in the primary wellborein accordance with an embodiment of the present invention.

FIG. 6 a is a schematic drawing depicting a cased lateral wellbore thatbranches from a primary wellbore, a downhole tool of the presentinvention disposed at a second location in the primary wellbore inaccordance with an embodiment of the present invention.

FIG. 6 b is a schematic drawing depicting an uncased lateral wellborethat branches from a primary wellbore, and a downhole tool of thepresent invention disposed at a second location in the primary wellborein accordance with an embodiment of the present invention.

FIG. 7 a is a schematic drawing depicting a cased lateral wellbore thatbranches from a primary wellbore, and a downhole tool of the presentinvention disposed in the primary wellbore in accordance with anembodiment of the present invention.

FIG. 7 b is a schematic drawing depicting an uncased lateral wellborethat branches from a primary wellbore, and a downhole tool of thepresent invention disposed in the primary wellbore in accordance with anembodiment of the present invention.

FIG. 8 a is a schematic drawing depicting a cased lateral wellbore thatbranches from a primary wellbore, and a downhole tool of the presentinvention disposed in the lateral wellbore in accordance with anembodiment of the present invention.

FIG. 8 b is a schematic drawing depicting an uncased lateral wellborethat branches from a primary wellbore, and a downhole tool of thepresent invention disposed in the lateral wellbore in accordance with anembodiment of the present invention.

FIG. 9 is a theoretical collar log of a primary wellbore in accordancewith an embodiment of the present invention.

FIG. 10 a is a theoretical collar log of a cased lateral wellbore inaccordance with an embodiment of the present invention.

FIG. 10 b is a theoretical collar log of an uncased lateral wellbore inaccordance with an embodiment of the present invention.

While the present invention is susceptible to various modifications andalternative forms, specific exemplary embodiments thereof have beenshown by way of example in the drawings and are herein described indetail. It should be understood, however, that the description herein ofspecific embodiments is not intended to limit the invention to theparticular forms disclosed, but on the contrary, the intention is tocover all modifications, equivalents, and alternatives falling withinthe spirit and scope of the invention as defined by the appended claims.

DETAILED DESCRIPTION

The present invention relates generally to lateral wellbore operations,and more particularly, to downhole tools that include a logging tool forlocating a lateral wellbore and associated methods.

According to the methods of the present invention, a logging tool may beused to verify entry into a lateral wellbore that branches from aprimary wellbore. The logging tool may be incorporated into any downholetool suitable for locating and entering a lateral wellbore from aprimary wellbore. The downhole tool comprising a logging tool may bepositioned in a primary wellbore containing a lateral wellbore thatbranches therefrom. Any suitable technique may be used to attempt entryinto the lateral wellbore that branches from the primary wellbore. Whileattempting entry, the logging tool may be used to generate a fingerprintas the logging tool is moved further into the primary and/or lateralwellbore. As defined herein, “fingerprint” is defined to mean any datathat identifies a wellbore based on characteristics of the wellboreand/or the formation surrounding the wellbore, such as the location (orlack thereof) of casing collars in the wellbore (e.g., a collar log) orthe emission of radiation by the formation (e.g., a gamma ray log or aneutron radiation log). The logging tool may be used to verify whetherthe attempt to enter the lateral wellbore was successful and, thus,whether the downhole tool has entered the lateral wellbore. Thefingerprint generated during the attempted entry should be compared witha fingerprint of the primary wellbore and/or a preexisting fingerprintof the lateral wellbore. If the fingerprint generated during theattempted entry is not equivalent to the fingerprint of the primarywellbore, then entry into the lateral wellbore was accomplished.Similarly, if the fingerprint generated during the attempted entry isequivalent to the preexisting fingerprint of the lateral wellbore, entryinto the lateral wellbore was accomplished. However, if the fingerprintgenerated during the attempted entry is equivalent to the fingerprint ofthe primary wellbore, entry into the lateral wellbore was notaccomplished. Similarly, if the fingerprint generated during theattempted entry is not equivalent to the fingerprint of the lateralwellbore, entry into the lateral wellbore was not accomplished. As thoseof ordinary skill in the art will appreciate, the steps of attempting toenter the lateral wellbore may be repeated until entry into the lateralwellbore is verified. Once entry into the lateral wellbore is verified,the downhole tool may be utilized to perform any suitable lateralwellbore operation.

The details of the present invention will now be described withreference to the accompanying figures. Referring now to FIG. 1, adownhole tool in accordance with the present invention is showngenerally by reference numeral 100. From upper end 102 to lower end 104,in one embodiment, downhole tool 100 includes logging tool 106,orienting sub 108, kickover knuckle joint 110, and wand 112. The variouscomponents of downhole tool 100, in certain embodiments, may beconnected to each other end to end with threaded connections. In someembodiments, downhole tool 100 provides for fluid communication throughits length. Optionally, downhole tool 100 may further include at leastone centralizer (not shown) to radially centralize downhole tool 100 ina wellbore.

Logging tool 106 may be used to verify entry into a lateral wellbore.Generally, a fingerprint of a wellbore may be generated using loggingtool 106. More particularly, logging tool 106 senses data that may beused to identify a wellbore. The sensed data may then be transmitted tothe surface (or other suitable location) and used to determine thelocation of and possible entry of the downhole tool 100 into the lateralwellbore. Locating and entering the lateral wellbore using downhole tool100 of the present invention will be discussed in more detail below.Furthermore, logging tool 106 may assist in establishing accurate depthcontrol for downhole tool 100, for example, by correlating thefingerprint generated using logging tool 106 with preexistingfingerprints for the wellbore so that measurements errors may becompensated for. Generally, the logging tool may be any suitable toolthat may be used in accordance with the present invention to generate afingerprint of a wellbore. In some embodiments, logging tool 106 is acasing collar locator, a radiation detection logging tool, or acombination thereof (e.g., a combination casing collar locator/radiationdetection logging tool).

Suitable casing collar locators for use in the present invention includeany casing collar locator that may be incorporated into the downholetool 100 of the present invention and used in generating a fingerprintof a wellbore. An example of a suitable casing collar locator is theDEPTHPRO casing collar locator, which is available from HalliburtonEnergy Services, Duncan, Okla. As those of ordinary skill in the artwill appreciate, other suitable casing collar locators may beincorporated into downhole tool 100 of the present invention. Referringnow to FIG. 2 a and FIG. 2 b, an example casing collar locator inaccordance with the present invention is shown generally by referencenumber 200. Casing collar locator 200 includes housing 201 and fluidflow passageway 202 extending through its length for providing fluidcommunication through housing 201. So that fluid flows thru casingcollar locator 200 and into lower end 104 of downhole tool 100 (shown onFIG. 1), plug 204 prevents the flow of fluid into a wellbore (not shown)and directs the flow of fluid from fluid flow passageway 202, throughside passageway 206, and out of casing collar locator 200 through lowerfluid flow passageway 208.

Casing collar locator 200 further includes collar detector 210, controlunit 212, battery pack 214, and a communication unit 216. While FIG. 2 ashows collar detector 210, control unit 212, battery back 214, andcommunication unit 216 as separate units, in other embodiments, theunits may be combined as appropriate. For example, in one embodiment,battery pack 214 and control unit 212 may be combined together as asingle unit prior to incorporation into casing collar locator 200.Collar detector 210, control unit 212, battery pack 214, andcommunication unit 216 may be electrically connected by suitable wiresand contacts and should be positioned within housing 201 withoutblocking fluid flow passageway 202. Those of ordinary skill in the artwill appreciate that collar detector 210 may include a source ofmagnetic field, e.g., magnets 215, or it may rely on the Earth'smagnetic field. Collar detector 210 further includes an electromagneticcoil assembly 218. Generally, control unit 212 houses electric circuitboards and other components 220. The electric circuit boards and othercomponents 220 may include central processors and other similar computerequipment capable of receiving and interpreting data as known to thoseskilled in the art. Battery pack 214 provides power for collar detector210, control unit 212, and communication unit 216, and may be anysuitable device for generating sufficient electricity to provide theneeded power, such as batteries or a generator. Communication unit 216provides the means for transmitting a pressure pulse detectable at thesurface or other suitable locations. Those of ordinary skill willrecognize that a wide variety of suitable pressure pulse generationsystems may be incorporated into casing collar locator 200. In oneembodiment, communication unit 216 may include solenoid valve 222, flowpassageway 224, piston 226, and spring 228.

As those of ordinary skill in the art will appreciate, collar detector210 is capable of sensing a change in the magnetic flux as downhole tool100 passes a casing collar as downhole tool 100 is moved within awellbore. Collar detector 210 generates a signal corresponding to thechange in magnetic flux, which is transmitted to control unit 212.Control unit 212 receives this signal and compares it to a predeterminedthreshold value. When this threshold value is met or exceeded by thechange in magnetic flux input to control unit 212, control unit 212directs communication unit 216 to transmit a pressure pulse to thesurface (or other suitable location). In some embodiments, a pressurepulse may transmitted to the surface by the blockage of fluid flowthrough fluid flow passageway 202 for a predetermined period of time(e.g., about 3 seconds). For example, control unit 212 may directsolenoid valve 222 to open. When solenoid valve 222 is open, fluid isdirected into flow passageway 224 where the fluid applies pressure topiston 226. As pressure is applied to piston 226, it lowers andcompresses spring 228 until piston 226 rests on shoulder 230. Whenresting on shoulder 230, piston 226 blocks side passageway 206. Thiscauses a pressure pulse in fluid flow passageway 202 detectable at thesurface that indicates a casing collar has been located from which acollar log may be generated. Those of ordinary skill in the art shouldbe able to select the appropriate mechanism for sensing the pressurepulse and recording it as a collar log. While casing collar locator 200has been described utilizing a mud-pulse telemetry system as the datatransmission system, the casing collar locator 200 may be equipped witha data transmission system for transmitting the sensed information alonga wireline (not shown) or in any other suitable manner.

Suitable radiation detection logging tools for use in the presentinvention include any radiation detection logging tool that may beincorporated into downhole tool 100 of the present invention and used ina generating a fingerprint of a wellbore. Referring now to FIG. 3, anexample radiation detection logging tool in accordance with the presentinvention is shown generally by reference number 300. Radiationdetection logging tool 300 includes housing 301 and fluid flowpassageway 302 extending through its length for providing fluidcommunication through housing 301. During logging operations, fluid flowpassageway 302 may be blocked by rupture disc 303, wherein rupture disc303 prevents communication of fluid pressure to lower end 104 ofdownhole tool 100 (shown on FIG. 1). One or ordinary skill in the art,with the benefit of this disclosure should be able to incorporate arupture disc into the radiation detection logging tool 300.

Radiation detection logging tool 300 further includes radiation detector304, control unit 306, battery pack 308, and communication unit 310.While FIG. 3 shows radiation detector 304, control unit 306, batteryback 308, and communication unit 310 as separate units, in otherembodiments, the units may be combined as appropriate. For example, inone embodiment, battery pack 308 and control unit 306 may be combinedtogether as a single unit prior to incorporation into radiationdetection logging tool 300. Radiation detector 304, control unit 306,battery pack 308, and communication unit 310 may be electricallyconnected by suitable wires and contacts and should be positioned withinhousing 301 without blocking fluid flow passageway 302. Generally,radiation detector 304 measures radiation in the wellbore as downholetool 100 is moved therein. For example, radiation detector 304 may be agamma ray detector that senses gamma counts emitted by formation rocks.Those of ordinary skill in the art will appreciate that radiationdetector 304 may any suitable device for measuring radiation emitted byformation rock, such as a gamma ray detector or a neutron detector.Generally, control unit 306 houses electric circuit boards and othercomponents 312. The electric circuit boards and other components 312 mayinclude central processors and other similar computer equipment capableof receiving and interpreting data as known to those skilled in the art.In some embodiments, radiation detector 304 may be turned on and off inresponse to signals received from control unit 306. Battery pack 308provides power for radiation detector 304, control unit 306, andcommunication unit 310, and may be any suitable device for generatingsufficient electricity to provide the needed power, such as batteries ora generator. Communication unit 310 provides the means for transmittinga pressure pulse detectable at the surface (or other suitable location).U.S. Pat. No. 5,586,084, the disclosure of which is incorporated hereinby reference in its entirety, describes a mud pulser that may be readilyadapted for use with communication unit 310. Alternative pressure pulsegeneration systems are well known in the art.

Radiation detector 304 is capable of measuring radiation (e.g., gammaray emissions, neutron emissions, or both) in the wellbore andgenerating a signal corresponding to the measured radiation. Radiationdetector 304 transmits this signal to control unit 306. Control unit 306receives this signal and directs communication unit 310 to generatedetectable changes in fluid pressure corresponding to the measuredradiation. For example, communication unit 310 may be capable ofproducing a series of pressure pulses detectable at the surface (orother suitable location). For example, communication unit 310 mayproduce pressure pulses within fluid flow passageway 302 that aredetectable at the surface which correspond to the measured radiationfrom which a gamma ray or a neutron radiation log may be generated.Those of ordinary skill in the art should be able to select theappropriate mechanism for sensing the pressure pulse and recording it asa gamma ray or neutron radiation log. While radiation detection loggingtool 300 has been described utilizing a mud-pulse telemetry system asthe data transmission system, the radiation detection logging tool 300may be equipped with a data transmission system for transmitting thesensed information along a wireline (not shown) or in any other suitablemanner.

Suitable combination casing collar locators/radiation detection loggingtools for use in the present invention include any combination casingcollar locator/radiation detection logging tool that may be incorporatedinto downhole tool 100 of the present invention and used in generating afingerprint of a wellbore. An example of a suitable combination casingcollar locator/radiation detection logging tool is described in commonlyowned U.S. patent application Ser. No. 10/796,548, filed on Mar. 9,2004, the disclosure of which is incorporated herein by reference in itsentirety. As those of ordinary skill in the art will appreciate, othersuitable combination casing collar locators/radiation detection loggingtools may be incorporated into downhole tool 100 of the presentinvention. Referring now to FIG. 4, an example combination casing collarlocator/radiation detection logging tool in accordance with the presentinvention is shown generally by reference number 400. Combination casingcollar locator/radiation detection logging tool 400 includes housing 401and fluid flow passageway 402 extending through its length for providingfluid communication through housing 401. During logging operations,fluid flow passageway 402 may be blocked by rupture disc 403, whereinrupture disc 403 prevents communication of fluid pressure to lower end104 of downhole tool 100 (shown on FIG. 1). One or ordinary skill in theart, with the benefit of this disclosure should be able to incorporate arupture disc into the combination casing collar locator/radiationdetection logging tool 400.

Combination casing collar locator/radiation detection logging tool 400further includes collar detector 404, radiation detector 406, controlunit 408, battery pack 410, and communication unit 412. While FIG. 4shows collar detector 404, radiation detector 406, control unit 408,battery back 410, and communication unit 412 as separate units, in otherembodiments, the units may be combined as appropriate. For example, inone embodiment, battery pack 410 and control unit 408 may be combinedtogether as a single unit prior to incorporation into combination casingcollar locator/radiation detection logging tool 400. Collar detector404, radiation detector 406, control unit 408, battery pack 410, andcommunication unit 412 may be electrically connected by suitable wiresand contacts and should be positioned within housing 401 withoutblocking fluid flow passageway 402. Those of ordinary skill in the artwill appreciate that collar detector 404 may include a source ofmagnetic field, e.g., magnets 414, or it may rely on the Earth'smagnetic field. Collar detector 404 further includes an electromagneticcoil assembly 416. Generally, radiation detector 406 measures radiationin a wellbore as downhole tool 100 is moved therein. For example,radiation detector 406 may be a gamma ray detector that senses gammacounts emitted by formation rocks. Those of ordinary skill in the artwill appreciate that radiation detector 406 may any suitable device formeasuring radiation emitted by formation rock, such as a gamma raydetector or a neutron detector. Generally, control unit 408 houseselectric circuit boards and other components 418. The electric circuitboards and other components 418 may include central processors and othersimilar computer equipment capable of receiving and interpreting data asknown to those skilled in the art. In some embodiments, radiationdetector 406 may be turned on and off in response to signals receivedfrom control unit 408. Battery pack 410 provides power for collardetector 404, radiation detector 406, control unit 408, andcommunication unit 412, and may be any suitable device for generatingsufficient electricity to provide the needed power, such as batteries ora generator. Communication unit 412 provides the means for transmittinga pressure pulse detectable at the surface (or other suitable location).U.S. Pat. No. 5,586,084 describes a mud pulser that may be readilyadapted for use with communication unit 412. Alternative pressure pulsegeneration systems are well known in the art.

As those of ordinary skill in the art will appreciate, collar detector404 is capable of sensing a change in the magnetic flux as downhole tool100 passes a casing collar as downhole tool 100 is moved within awellbore. Collar detector 404 generates a signal corresponding to thechange in magnetic flux and transmits it to control unit 408. Controlunit 408 receives the signal and compares this change in magnetic fluxto a predetermined threshold value. When this threshold value is met orexceeded by the change in magnetic flux input to control unit 408,control unit 408 directs communication unit 412 to transmit this data tothe surface (or other suitable location). For example, communicationunit 412 may produce detectable changes in pressure within fluid flowpassageway 402. These pressure pulses are detectable at the surface andindicate a casing collar has been located from which a collar log may begenerated. Radiation detector 406 is capable of measuring radiation(e.g., gamma ray emissions, neutron emissions, or both) in the wellboreand generating a signal corresponding to the measured radiation.Radiation detector 406 transmits this signal to control unit 408.Control unit 408 receives this signal and directs communication unit 412to transmit this data to the surface (or other suitable location) in themanner described above. Those of ordinary skill in the art should beable to select the appropriate mechanism for sensing the pressurechanges in fluid flow passageway 402 and recording it as a collar log,gamma ray log, or a neutron radiation log. While combination casingcollar locator/radiation detection logging tool 400 has been describedutilizing a mud-pulse telemetry system as the data transmission system,it may be equipped with a data transmission system for transmitting thesensed information along a wireline (not shown) or in any other suitablemanner.

Referring again to FIG. 1, orienting sub 108 may be connected betweenlogging tool 106 and kickover knuckle joint 110. Orienting sub 108 maybe any known device for rotating kickover knuckle joint 110 and wand 112about the longitudinal axis LA of downhole tool 100. Examples ofsuitable devices include, but are not limited to, an indexing tool or acontinuously run motor. Where an indexing tool is employed, the indexingtool may provide a rotation of a fixed number of degrees (e.g., 45degrees) about the LA of downhole tool 100 when the indexing tool isactivated. In one embodiment, the indexing tool is hydraulicallyactivated so that it is activated when the flow of fluid through theindexing fluid is started and stopped. Where a continuously run motor isemployed, such motor may provide continuous 360-degree rotation aboutthe LA of downhole tool 100. One of ordinary skill in the art with thebenefit of this disclosure will be able to select and employ theappropriate orienting sub 108 for a particular application.

Kickover knuckle joint 110 may be connected to orienting sub 108.Kickover knuckle joint 110 may be any suitable device adapted to deflectwand 112 with respect to the LA of downhole tool 100. Kickover knucklejoint 110 attaches wand 112 to downhole tool 100. In some embodiments,kickover knuckle joint 110 is a selectively activated knuckle joint. Anexample of a suitable selectively activated knuckle joint is the“Hydraulic Kickover Joint”, which is available from PCE, Dorset, UnitedKingdom. As will be appreciated by those skilled in the art, theselectively activated knuckle joint may not bend until it is activated.In a preferred embodiment, the selectively activated knuckle joint ishydraulically activated, wherein the selectively activated knuckle jointbends when a predetermined hydraulic pressure is reached therein. Theactivation of the selectively activated knuckle joint may then becontrolled from the surface by controlling the hydraulic pressure withinthe selectively activated knuckle joint. Other suitable kickover knucklejoints 110 include, but are not limited to, restricted ball joints, pinjoints, bourdon tubes, or an asymmetrically slotted member with internalpressurization means. One of ordinary skill in the art with the benefitof this disclosure should be able to select and implement theappropriate kickover knuckle joint 110 for a particular application.

Wand 112 is the bottom portion of downhole tool 100 that selectivelydeflects from alignment with the LA of downhole tool 100 to enter alateral wellbore. Wand 112 is connected to kickover knuckle joint 110.In some embodiments, there may be more than one wand (not shown) at thebottom of downhole tool 100. Wand 112 should be of a length sufficientso that one end of wand 112 deflects into a lateral wellbore when itpasses the lateral wellbore. As those of ordinary skill in the art willappreciate, wand 112 will be longer in casing with larger casing sizesthan in smaller casing sizes. In some embodiments, wand 112 may beadjustable in length, for example, by telescoping. In some embodiments,the shape of wand 112 may be varied so long as the wand 112 is suitablefor use in the present invention, for example, wand 112 may have somecurvature or angularity (not shown).

As will be understood by those in skilled in the art, wand 112 furthermay include components useful in lateral wellbore operations, interalia, for analyzing, treating, stimulating, and/or cementing the lateralwellbore. For example, as shown in FIG. 1, wand 112 may include a noseor toe 114 attached at an end thereof. In some embodiments, nose 114 maycontain one or more ports. Even further, for example, the ports in nose114 may include jetting nozzles disposed therein. Furthermore,components for analyzing and/or treating wellbores may also be locatedat other locations within downhole tool 100.

Wand 112 may be deflected with respect to the. LA of downhole tool 100by kickover knuckle joint 110 to a predetermined maximum deflectionangle α. The maximum deflection angle α of wand 112 by kickover knucklejoint 110 depends on a number of factors, including the inner diameterof the primary wellbore, the length of wand 112, and other factors knownto those of ordinary skill in the art. Generally, a suitable maximumdeflection angle α for wand 112 with respect to the LA of downhole tool100 may be in the range from about 3 degrees to about 30 degrees.

Downhole tool 100 may further include an optional centralizer forcentralizing downhole tool 100 in a lateral and/or primary wellbore. Anynumber or type of centralizers may be utilized in accordance with thepresent invention as desired by one skilled in the art. As those ofordinary skill in the art will appreciate, the length of wand 112 may beadjusted based on whether a centralizer is used with downhole tool 100.

Referring now to FIG. 5 a through FIG. 8 b an embodiment for locatingand entering a lateral wellbore from a primary wellbore is illustrated.Downhole tool 100 may be the same as those previously described and mayinclude logging tool 106, orienting sub 108, kickover knuckle joint 110,wand 112, and nose 114. Downhole tool 100 is shown disposed in primarywellbore 500 that penetrates subterranean formation 502. Generally,primary wellbore 500 may be lined with a slotted liner or casing string,e.g., primary casing 504, that may be cemented to subterranean formation502. Primary casing 504 may include sections of pipe connected by one ormore casing collars 506. Example depths for one or more casing collars506 are indicated on FIG. 5 a through FIG. 8 b. Those of ordinary skillin the art will appreciate the circumstances when primary wellbore 500should or should not be cemented. Even though FIG. 5 a through FIG. 8 bdepict primary wellbore 500 as a vertical wellbore, the downhole tool100 and methods of the present invention may be suitable in generallyhorizontal, generally vertical, or otherwise formed portions of wells.

Lateral wellbore 508 branches from primary wellbore 500 at junction 510.Primary wellbore 500 and lateral wellbore 508 may be drilled intosubterranean formation 502 using any suitable drilling technique. Asdesired, lateral wellbore 508 may be lined with a casing string orslotted liner, e.g., lateral casing 512, as shown in FIG. 5 a, or leftopenhole, as shown in FIG. 5 b. In the embodiments where lateralwellbore 508 is lined with lateral casing 512, lateral casing 512 may ormay not be cemented to subterranean formation 502. Furthermore, lateralcasing 512 may include sections of pipe connected by one or more lateralcasing collars 514. Example depths for one or more lateral casingcollars 514 are indicated on FIGS. 5 a, 6 a, 7 a, and 8 a. Those ofordinary skill in the art will appreciate the circumstances when lateralwellbore 508 should or should not be cased and whether such casingshould or should not be cemented.

As illustrated in FIG. 5 a for a cased lateral wellbore 508 and FIG. 5 bfor an uncased lateral wellbore 508, downhole tool 100 should bepositioned in primary wellbore 500. In some embodiments, primarywellbore 500 may be positioned at a first location that is below orposterior to the estimated location of junction 510. In one embodiment,the first location may be about 100 feet below or posterior to theestimated location of junction 510. While positioning downhole tool 100at the first location, wand 112 may be maintained at angle coincidentwith or substantially coincident with the LA of downhole tool 100.

Next, as illustrated in FIG. 6 a for a cased lateral wellbore 508 andFIG. 6 b for an uncased lateral wellbore 508, downhole tool 100 may bepositioned in primary wellbore 500 at a second location above oranterior to the estimated location of junction 510. In one embodiment,the second location may be about 100 feet above or anterior to theestimated location of junction 510. While positioning downhole tool 100at the second location, wand 112 may be maintained at an anglecoincident with or substantially coincident with the LA of downhole tool100.

Furthermore, while raising or retrieving downhole tool 100 to the secondlocation, logging tool 106 may be used in generating a fingerprint ofprimary wellbore 500. As previously discussed, this fingerprint may be agamma ray log, a neutron radiation log, or a collar log of primarywellbore 500. For example, radiation emissions may be measured bylogging tool 106 (e.g., a radiation detection logging tool) andtransmitted to the surface (or other suitable location) whilepositioning downhole tool 100 in primary wellbore 500. The measuredradiation emissions may be recorded as a gamma ray log or a neutronradiation log. Even further, for example, the location of one or morecasing collars 506 in primary wellbore 500 may be sensed with loggingtool 106 (e.g., a casing collar locator) and transmitted to the surface(or other suitable location) while positioning downhole tool 100 inprimary wellbore 500. This sensed location(s) may be recorded as acollar log. Referring now to FIG. 9, depicted is a theoretical collarlog that is a graphical representation of pressure versus depth thatindicates the sensed location of one or more casing collars 506 inprimary wellbore 500. The pressure spikes on the collar log indicate thesensed location of one or more casing collars 506. Among other things,this collar log may be used by an operator to correct his depth countersto compensate for measurement errors that may occur while runningdownhole tool 100 in primary wellbore 500. As one of ordinary skill inthe art will appreciate, where a suitable fingerprint (e.g., a collarlog, gamma ray log, neutron radiation log) of primary wellbore 500 isavailable downhole tool 100 may first be positioned in primary wellbore500 at a second location without initially positioning downhole tool 100at the first location.

Referring again to FIG. 6 a and FIG. 6 b, once downhole tool 100 ispositioned at the second location, lower end 104 of downhole tool 100should be deflected with respect to the LA of downhole tool 100. Forexample, kickover knuckle joint 110 should deflect wand 112 with respectto the LA of downhole tool 100 so that nose 114 is in contact with aninner surface of primary casing 504. In some embodiments, this may beaccomplished by increasing the flow rate through downhole tool 100 untilthe hydraulic pressure therein is sufficient to deflect wand 112. Theenergy used to deflect wand 112 should be maintained and generallyshould be greater than the energy sufficient for nose 114 to reach theinner surface of primary casing 504. The inner surface of primary casing504 should constrain wand 112 and prevent it from further deflection.Those of ordinary skill in the art will appreciate that wand 112 maydeflect even further with respect to the LA of downhole tool 100 if theconstraining force of primary casing 504 were removed.

Referring now to FIG. 7 a for a cased lateral wellbore and FIG. 7 b foran uncased lateral wellbore, downhole tool 100 may next be moved (e.g.,lowered) from the second location in primary wellbore 500 towardsjunction 510. As downhole tool 100 is moved, nose 114 should remain incontact with the inner surface of primary casing 504. The energy used todeflect wand 112 should be maintained while moving downhole tool 100 inprimary wellbore 500. When downhole tool 100 passes junction 510, lowerend 104 (shown in FIG. 1) of downhole tool 100 enters lateral wellbore508. For example, when junction 510 is reached, the constraining forceof primary casing 504 is removed and wand 112 deflects further withrespect to the LA of downhole tool 100 so that toe 114 of wand 112 mayenter lateral wellbore 508. In some embodiments, kickover knuckle joint110 and wand 112 may be rotated using orienting sub 108 while movingdownhole tool 100 towards junction 510.

Referring now to FIG. 8 a for a cased lateral wellbore 508 and FIG. 8 bfor an uncased lateral wellbore 508, downhole tool 100 may next be movedinto lateral wellbore 508 behind toe 114. While moving downhole tool 100from the second location in primary wellbore 500 towards junction 510and into lateral wellbore 508, logging tool 106 should be used to verifyentry of downhole tool 100 into lateral wellbore 508. For example,logging tool 106 should be used to generate a fingerprint as downholetool 100 moves from the second location in primary wellbore 500 and intolateral wellbore 508. As previously discussed, the fingerprint may be agamma ray log, a neutron radiation log, or a collar log. For example,radiation emissions may be measured by logging tool 106 (e.g., aradiation detection logging tool) and transmitted to the surface (orother suitable location) while moving downhole tool 100 into lateralwellbore 508. The sensed radiation emissions may be recorded as a gammaray log or a neutron radiation log. Even further, for example, thelocation of one or more lateral casing collars 514 in lateral wellbore508 may be sensed with logging tool 106 (e.g., a casing collar locator)and transmitted to the surface (or other suitable location) while movingdownhole tool 100 into lateral wellbore 508. This sensed location(s) maybe recorded as a collar log. Referring now to FIG. 10 a, depicted is atheoretical collar log that is a graphical representation of pressureversus depth that indicates the sensed location of one or more lateralcasing collars 514 in lateral wellbore 508, wherein lateral wellbore 508is cased. Referring now to FIG. 10 b, depicted is a theoretical collarlog that is a graphical representation of pressure versus depth thatindicates the presence, or lack thereof, of casing collars in lateralwellbore 508, wherein lateral wellbore 508 is uncased. The pressurespikes on these collar logs indicate the sensed location of one or morelateral casing collars 514. As will be understood by those of ordinaryskill in the art the one or more casing collars indicated on the collarlog of lateral wellbore 508 may be a primary casing collar 506 thatlogging tool 106 passes prior to its entry into lateral wellbore 508.

To verify entry into lateral wellbore 508, the fingerprint of lateralwellbore 508, obtained as described above, may be compared with anysuitable fingerprint of primary wellbore 500. For example, determiningwhether downhole tool 100 has entered into lateral wellbore 508 maycomprise comparing a collar log sensed by a casing collar locator with acollar log of primary wellbore 500. Even further, for example,determining whether the downhole tool 100 has entered lateral wellbore508 may comprise comparing a gamma ray or a neutron radiation log sensedby a radiation detection logging tool with a gamma ray or a neutronradiation log of primary wellbore 500. In some embodiments, thefingerprint of primary wellbore 500 may be a fingerprint obtained asdescribed above when navigating downhole tool 100 within primarywellbore 500 or any suitable fingerprint of primary wellbore 500 that isavailable. If the fingerprint of lateral wellbore 508 is not equivalentto the fingerprint of primary wellbore 500, then entry into lateralwellbore 508 is verified and downhole tool 100 successfully located andentered lateral wellbore 508. Furthermore, in some instances, there maybe a suitable preexisting fingerprint of lateral wellbore 508. Thepreexisting fingerprint of lateral wellbore 508 may have been generatedduring previous operations in lateral wellbore 508, such as drilling.Where a suitable preexisting fingerprint of lateral wellbore 508 ispresent, the fingerprint of lateral wellbore 508 obtained as describedabove may be compared to the preexisting fingerprint of lateral wellbore508 to verify whether downhole tool 100 has entered lateral wellbore508. For example, determining whether the downhole tool 100 has enteredlateral wellbore 508 may comprise comparing a gamma ray or a neutronradiation log sensed by a radiation detection logging tool with apre-existing gamma ray or a neutron radiation log of lateral wellbore508. If the fingerprint of lateral wellbore 508 is equivalent to thepre-existing fingerprint of lateral wellbore 508, then entry intolateral wellbore 508 is verified and downhole tool 100 successfullylocated and entered lateral wellbore 508. As those of ordinary skill inthe art will appreciate, the comparison to the pre-existing fingerprintof lateral wellbore 508 may be done in combination with or independentlyto a comparison with the fingerprint of primary wellbore 500.

After entry into lateral wellbore 508 has been verified, lower end 104(e.g., wand 114) of downhole tool 100 may be returned to an anglecoincident with or substantially coincident with the LA of downhole tool100 as illustrated on FIG. 8 a and FIG. 8 b. In some embodiments,lateral wellbore operations in lateral wellbore 508 may then beconducted.

However, if the fingerprint of lateral wellbore 508 is equivalent to thefingerprint of primary wellbore 500 and/or the fingerprint of lateralwellbore 508 is not equivalent to the preexisting fingerprint of lateralwellbore 508, then downhole tool 500 did not locate and enter lateralwellbore 508. For example, junction 510 may have been on an oppositeside of primary wellbore 500 than where nose 114 was deflected. As oneof ordinary skill in the art will appreciate, downhole tool 100 then isactually in primary wellbore 500 and the fingerprint obtained is not thefingerprint of lateral wellbore 508 but is instead the fingerprint ofprimary wellbore 500. Downhole tool 100 may then be returned to thesecond location above or anterior to junction 510 and orienting sub 108may be used to rotate wand 112 about the LA of downhole tool 100. Theabove procedure may then be repeated until it is determined using theabove verification procedures whether downhole tool 100 has successfullylocated and entered lateral wellbore 508.

Therefore, the present invention is well adapted to carry out theobjects and attain the ends and advantages mentioned as well as thosewhich are inherent therein. While numerous changes may be made by thoseskilled in the art, such changes are encompassed within the spirit ofthis invention as defined by the appended claims.

1. A method for use in lateral wellbore operations, comprising: enteringa lateral wellbore from a primary wellbore with a tool comprising alogging tool; and verifying entry into the lateral wellbore using thelogging tool.
 2. The method of claim 1 wherein the logging tool is acasing collar locator, a radiation detection logging tool, or acombination thereof.
 3. The method of claim 1 wherein verifying entryinto the lateral wellbore comprises: generating a fingerprint of thelateral wellbore using the logging tool; and comparing the fingerprintof the lateral wellbore with a fingerprint of the primary wellboreand/or a pre-existing fingerprint of the lateral wellbore.
 4. The methodof claim 3 wherein the fingerprint is a collar log, a gamma ray log, ora neutron radiation log.
 5. The method of claim 3 wherein thefingerprint of the primary wellbore was generated using the loggingtool.
 6. The method of claim 1 further comprising moving the tool in theprimary wellbore towards a junction, wherein the lateral wellborebranches from the primary wellbore at the junction.
 7. The method ofclaim 6 further comprising positioning the tool at a location anteriorto the junction prior to moving the tool towards the junction.
 8. Themethod of claim 7 further comprising generating a fingerprint of theprimary wellbore using the logging tool while positioning the tool at alocation anterior to the junction.
 9. The method of claim 7 furthercomprising positioning the tool at a location posterior to the junctionprior to positioning the tool at a location anterior to the junction.10. The method of claim 1 further comprising conducting a lateralwellbore operation subsequent to verifying entry into the lateralwellbore.
 11. A method of locating a lateral wellbore of a multilateralwell, wherein the multilateral lateral well comprises a primary wellboreand a lateral wellbore that branches from the primary wellbore at ajunction, comprising: positioning a tool comprising a logging toolwithin the multilateral well; moving the tool within the multilateralwell; and determining whether the tool has entered the lateral wellboreusing the logging tool.
 12. The method of claim 11 wherein determiningwhether the tool has entered the lateral wellbore comprises comparing afingerprint generated by the logging tool while moving the tool with afingerprint of the lateral wellbore and/or a fingerprint of the primarywellbore.
 13. The method of claim 11 wherein the logging tool is acasing collar locator, a radiation detection logging tool, or acombination thereof.
 14. The method of claim 11 further comprisinggenerating a fingerprint of the primary wellbore using the logging tool.15. The method of claim 14 wherein the fingerprint is a collar log, agamma ray log, or a neutron radiation log.
 16. The method of claim 11wherein positioning the tool within the multilateral well comprisespositioning the tool at a first location in the primary wellboreposterior to the junction.
 17. The method of claim 16 whereinpositioning the tool within the multilateral well further comprisespositioning the tool at a second location anterior to the junctionsubsequent to positioning the tool at the first location in the primarywellbore.
 18. The method of claim 17 further comprising generating afingerprint of the primary wellbore while positioning the tool at thesecond location in the primary wellbore.
 19. The method of claim 17wherein moving the tool within the multilateral well comprises movingthe tool from the second location in the primary wellbore towards thejunction.
 20. The method of claim 11 further comprising entering thelateral wellbore while moving the tool within the multilateral well. 21.A method of locating and entering a lateral wellbore from a primarywellbore, wherein the lateral wellbore branches from the primarywellbore at a junction, comprising: (a) positioning a downhole tool inthe primary wellbore at a first location posterior to the junction,wherein the downhole tool comprises a casing collar locator; (b)positioning the downhole tool in the primary wellbore at a secondlocation anterior to the junction subsequent to positioning the downholetool in the primary wellbore at the first location; (c) moving thedownhole tool from the second location towards the junction; and (d)determining whether the downhole tool has entered the lateral wellboreusing the casing collar locator.
 22. The method of claim 21 whereindetermining whether the downhole tool has entered the lateral wellborecomprises comparing a collar log of the lateral wellbore sensed by thecasing collar locator with a collar log of the primary wellbore.
 23. Themethod of claim 21 further comprising rotating the downhole tool about alongitudinal axis of the downhole tool subsequent to determining whetherthe downhole tool has entered the lateral wellbore.
 24. The method ofclaim 21 further comprising repeating steps (b) through (d) subsequentto determining whether the downhole tool has entered the lateralwellbore.
 25. The method of claim 21 wherein the first location is about100 feet posterior to the junction.
 26. The method of claim 21 furthercomprising sensing the location of one or more casing collars in theprimary wellbore with the casing collar locator while positioning thedownhole tool in the primary wellbore at the second location.
 27. Themethod of claim 21 wherein the second location is about 100 feetanterior to the junction.
 28. The method of claim 21 further comprisingdeflecting an end of the downhole tool with respect to a longitudinalaxis of the downhole tool.
 29. The method of claim 28 wherein the end ofthe downhole tool enters the lateral wellbore when the downhole toolpasses the junction.
 30. The method of claim 29 further comprisingmoving the downhole tool into the lateral wellbore.
 31. The method ofclaim 29 further comprising sensing the location of one or more casingcollars within the lateral wellbore.
 32. The method claim 30 furthercomprising returning the end of the downhole tool to an anglesubstantially coincident to the longitudinal axis of the downhole toolafter the downhole tool moves into the lateral wellbore.
 33. The methodof claim 21 further comprising sensing the location of one or morecasing collars within the primary wellbore.
 34. A method of locating andentering a lateral wellbore from a primary wellbore, wherein the lateralwellbore branches from the primary wellbore at a junction, comprising:(a) positioning a downhole tool comprising a radiation detection loggingtool in the primary wellbore; (b) moving the downhole tool towards thejunction; and (c) determining whether the downhole tool has entered thelateral wellbore using the radiation detection logging tool.
 35. Themethod of claim 34 wherein determining whether the downhole tool hasentered the lateral wellbore comprises comparing a gamma ray log of thelateral wellbore generated using the radiation detection logging toolwith a gamma ray log of the primary wellbore and/or a pre-existing gammaray log of the lateral wellbore.
 36. The method of claim 34 whereindetermining whether the downhole tool has entered the lateral wellborecomprises comparing a neutron radiation log of the lateral wellboregenerated using the radiation detection logging tool with a neutronradiation log of the primary wellbore and/or a pre-existing neutronradiation log of the lateral wellbore.
 37. The method of claim 34further comprising rotating the downhole tool about a longitudinal axisof the downhole tool subsequent to determining whether the downhole toolhas entered the lateral wellbore.
 38. The method of claim 37 furthercomprising repeating steps (a) through (c) subsequent to determiningwhether the downhole tool has entered the lateral wellbore.
 39. Themethod of claim 34 further comprising generating a gamma ray log of theprimary wellbore while positioning the downhole tool in the primarywellbore.
 40. The method of claim 34 further comprising generating aneutron radiation log of the primary wellbore while positioning thedownhole tool in the primary wellbore.
 41. The method of claim 34further comprising deflecting an end of the downhole tool with respectto a longitudinal axis of the downhole tool.
 42. The method of claim 41wherein the end of the downhole tool enters the lateral wellbore whenthe downhole tool passes the junction.
 43. The method of claim 42further comprising moving the downhole tool into the lateral wellbore.44. The method of claim 43 further comprising measuring radiationemissions within the lateral wellbore.
 45. The method of claim 44wherein the radiation emissions are gamma ray emissions, neutronradiation emissions, or both.
 46. The method claim 43 further comprisingreturning the end of the downhole tool to an angle substantiallycoincident to the longitudinal axis of the downhole tool after thedownhole tool moves into the lateral wellbore.
 47. The method of claim34 further comprising measuring radiation emissions within the primarywellbore.
 48. A downhole tool, comprising: a logging tool; a kickoverknuckle joint connected to the logging tool; and a wand connected to thekickover knuckle joint.
 49. The downhole tool of claim 48 wherein thelogging tool is a casing collar locator, a radiation detection loggingtool, or a combination thereof.
 50. The downhole tool of claim 49wherein the logging tool comprises: a housing; a fluid passageway forproviding fluid communication through the housing; and a radiationdetector positioned within the housing for measuring radiation in awellbore and for generating a signal corresponding to the measuredradiation;
 51. The downhole tool of claim 50 wherein the radiationdetector comprises a gamma ray detector or a neutron detector.
 52. Thedownhole tool of claim 50 wherein the logging tool further comprises: acommunication unit positioned within the housing; a control unitpositioned within the housing for receiving the signal from theradiation detector and for directing the communication unit to transmita pressure pulse; and a battery pack for powering the radiationdetector, the control unit, and the communication unit.
 53. The downholetool of claim 49 wherein the casing collar locator comprises: a housing;a fluid passageway for providing fluid communication through thehousing; and a casing collar detector positioned within the housing forsensing the location of one or more casing collars in a wellbore and forgenerating a signal corresponding to the sensed location.
 54. Thedownhole tool of claim 53 wherein the radiation detection logging toolcomprises: a communication unit positioned within the housing; a controlunit positioned within the housing for receiving the signal from thecasing collar detector and directing the communication unit to transmita pressure pulse; and a battery pack for powering the casing collardetector, the control unit, and the communication unit.
 55. The downholetool of claim 49 wherein the combination casing collar locator/radiationdetection logging tool comprises: a housing; a fluid passageway forproviding fluid communication through the housing; a casing collardetector positioned within the housing for sensing the location of oneor more casing collars in a wellbore and for generating a signalcorresponding to the sensed location; and a radiation detectorpositioned within the housing for measuring radiation in the wellboreand for generating a signal corresponding to the measured radiation. 56.The downhole tool of claim 55 wherein the combination casing collarlocator/radiation detection logging tool further comprises: acommunication unit positioned within the housing; a control unitpositioned within the housing for receiving the signal from the casingcollar detector and the radiation detector, and for directing thecommunication unit to transmit a pressure pulse; and a battery pack forpowering the casing collar detector, the radiation detector, the controlunit, and the communication unit.
 57. The downhole tool of claim 48further comprising an orienting sub connected between the logging tooland the kickover knuckle joint.
 58. The downhole tool of claim 57wherein the orienting sub includes an indexing tool or a continuouslyrun motor.
 59. The downhole tool of claim 57 wherein the orienting subis operated hydraulically.
 60. The downhole tool of claim 48 wherein thekickover knuckle joint is a selectively activated knuckle joint.
 61. Thedownhole tool of claim 48 wherein the kickover knuckle joint is operatedhydraulically.
 62. The downhole tool of claim 48 wherein the wand isadjustable in length.
 63. The downhole tool of claim 48 wherein the wandincludes a nose attached at an end thereof.
 64. The downhole tool ofclaim 63 wherein the nose contains one or more ports.
 65. The downholetool of claim 48 wherein the wand may be deflected with respect to thelongitudinal axis of the downhole tool to a predetermined maximumdeflection angle.
 66. The downhole tool of claim 65 wherein thepredetermined maximum deflection angle is in the range of from about 3degrees to about 30 degrees.